This blog posting is the fifth of a series of five postings from the 2014 year-end energy briefing.

This article was first published in The Metropolitan Corporate Counsel, January 2015 issue.

Burdick: For our final topic, the discussion will be led by Steve Davis, a partner in the Global Energy Practice, Ed Rubinoff, a partner in the International Trade Practice, and Vera Neinast, a senior counsel in the Energy Regulation, Markets and Enforcement practice. Steve, Ed and Vera will discuss U.S. energy exports.

Davis: While exports of finished petroleum products from the U.S. have been steadily rising since 1984, that upward curve has been much sharper during the past seven or eight years. A principal reason is that these exports are not restricted to the same degree as LNG and crude oil exports. With respect to liquefied petroleum gas (LPG), the exports curve is similar in shape over the same period, with the sharp rise beginning around 2008. After 2011, this pattern will be even more pronounced because of the number of very large LPG export projects currently underway. In fact, several more are under negotiation as we speak.

These exports are not limited to natural gas and liquids; coal also is a significant U.S. export and, despite expected changes, coal will continue to be a very significant part of the fuel mix in the U.S. power generation sector. We will have a large component of coal exports to Asia and particularly to China.

In the past year or so, U.S. crude oil production has surpassed crude oil net imports for the first time since 1994. With respect to the effect of this increase in domestic production and the concomitant effect on gasoline prices, several large economic consulting groups here in the U.S. estimate that there would be a decrease in gasoline prices associated with an increase in U.S. crude production and in crude oil exports from the U.S.

Rubinoff: Since 1975, in the wake of the Arab oil embargo, the U.S. has essentially banned the export of crude oil – with some limited exceptions carved out by statute – under a regulatory scheme administered by the Commerce Department's Bureau of Industry and Security (BIS). The regulatory scheme remained in place for several decades because the situation didn't change much. The United States was a large importer of crude oil and didn't produce enough to export crude. But market and economic conditions have now changed dramatically, reflecting stable demand coupled with the increased U.S. production of crude oil caused by new discoveries and the application of new technologies, which has created pressure to find new markets. Legislative efforts to lift or ease the export ban, however, have not succeeded thus far.

The exceptions for granting licenses to export crude oil are limited to specific sources and circumstances and don't afford the opportunity to export much crude oil. Exports to Canada have been increasing but don’t account for much volume. The statute that banned exports also provides a broad national-interest standard for granting licenses, but, as implemented thus far by the BIS regulations, that exception has rarely been used and has been used only to license exports that involve swaps, where domestic crude is exchanged for an equal or greater quantity or quality of foreign crude oil or refined products under prescribed conditions. There's also been the possibility of exporting refined petroleum products, which, unlike crude oil, largely can be exported without getting a license. Statistics indicate that there are increasing exports of crude by refiners, but that avenue of exporting crude is constrained by refinery capacity, which is now pretty much capped out.

These export limitations have focused more attention on the definition of “crude oil” to determine applicability of the restrictions. The regulatory definition adopted by BIS states that crude oil that is processed through a “distillation tower” is no longer crude oil and can be exported as a petroleum product. Forty years ago, when the definition was adopted, regulators probably had in mind a large distillation tower at a refinery, but technology has advanced over time, and now various types of equipment can be used at the wellhead and before crude oil is transported to a refinery to process it further and to separate it into component hydrocarbons.

These advances raise questions about what type of processing is sufficient to transform crude oil into a petroleum product. This past year, two companies, one a producer and one a midstream operator, sought rulings from BIS regarding the classification of lease condensate (considered under the BIS definition to be crude oil) that is partially processed after production. The companies obtained rulings that their forms of processing were adequate to convert the crude oil into petroleum products. Unfortunately, these rulings are confidential; they're not published, and I've not seen them, so I can’t tell you exactly what processing techniques were involved in those cases. They also are limited in their legal application, both to the applicants and to the specific facts presented.

Reaction to these two rulings has been mixed. Many on Capitol Hill claimed that BIS usurped its limited jurisdiction, while BIS asserts that it's simply interpreting its rules and applying them appropriately. In any event, BIS has not issued any further rulings, although it is rumored to be developing some sort of guidance for publication. From my own conversations with BIS, I can tell you that there is no bright line test currently in mind. What they are looking for is some type of processing beyond simple stabilization and simple separation. I've been told that a splitter would be considered a functional equivalent of the distillation tower and would be adequate.

Without more guidance or rulings coming out of BIS, companies are left to their own devices and can self-classify under the regulatory scheme if they feel that what they do in processing crude oil is adequate to meet the standards. There are reports that a number of companies have done this, including BHP Billiton, which has exported a shipment of crude oil based on its own self-determination. That leaves us with an agency that is willing to talk to producers and give informal guidance but is no longer issuing rulings, and no other type of pronouncement appears to be forthcoming.

Of course, companies can self-classify, but that entails risk because those determinations can always be challenged, first of all, by Customs at the border when the shipment is ready to leave and, afterwards, by BIS if it disagrees with the classification, thus exposing the company to a penalty. Finally, there’s always the licensing route for getting an export license under the current exceptions and possibly trying to make a more convincing argument under the national-interest standard.

Neinast: All exports of natural gas from the U.S., including LNG, require approval from the Department of Energy (DOE). I'm going to discuss two recent regulatory developments affecting LNG exports. First, the DOE issued new procedures in August that apply to the processing of non-Free-Trade-Agreement (FTA) export applications, i.e., applications for export to countries other than those countries with which the U.S. currently has a Free Trade Agreement. Under the new procedures, the DOE will no longer issue conditional approvals but, instead, will issue final approval once the facility has completed the environmental review process before the siting agency, either FERC or MARAD (the U.S. Maritime Administration).

The DOE will conduct its own separate environmental analysis, but it will use the same NEPA documents prepared by the siting agency. The practical effect is that sponsors will have to expend millions of dollars plus a year or two of time to complete the NEPA process in a proceeding before the siting agency – all in advance of being able to find out whether the DOE will approve the export of the commodity itself.

The second recent development is that, beginning in September of this year, we have new procedures applicable to change-in-control applications for all imports and exports of natural gas. DOE considers a change in control to be material; therefore, these filings are considered mandatory. The DOE has established a rebuttable presumption that control exists when an entity acquires a 10 percent interest in the applicant or license holder, or ownership or the power to vote, directly or indirectly, 10 percent or more of the voting securities.

How the DOE processes change-in-control applications varies depending on whether the change in control applies to a pending or a final export authorization, and also whether the export is proposed to FTA or non-FTA countries. This new policy has the potential to increase the regulatory burden on project sponsors. Unlike at FERC, there's no way to structure the change in control to avoid having to make a regulatory filing. This low threshold limit of 10 percent has the potential to force an applicant to make multiple change-in-control filings, and each one provides protesters with yet another vehicle to challenge the export application.

Finally, please note that a change in control may also require approval from other agencies, such as CFIUS (Committee on Foreign Investment in the U.S.), since the DOE approval for the commodity export license does not encompass CFIUS approval.

Burdick: I’d like to thank all the presenters. We plan to continue these energy briefings in 2015 and would welcome feedback on potential topics or formats for future briefings.